EVs and the grid

A group of electric vehicle taxis using fast charging infrastructure at Amsterdam Airport Schiphol, the Netherlands. Image: ArtbyBart via iStock

Can our grid cope with the extra charging load if we all switch to electric vehicles? A recent report by Australian company Evenergi examines the issues.

If well planned, the transition to electric vehicles will lead to a significant reduction in greenhouse gas emissions, along with other potential benefits such as improved GDP and lower costs for consumers (in the longer term). But can the grid cope? According to a recent report, the short answer is yes, and there can even be positives for utilisation of grid assets and grid stability. But some planning is clearly needed to ensure we capture the benefits without significant issues.

The report, funded by ARENA, the SA government, SA Power Networks and Evenergi, considered both the capacity challenges and renewable energy opportunities for EVs on the South Australian grid.

The report’s main focus is on charging ‘hotspots’. It considers the charging scenarios that might lead to capacity issues (such as a concentration of ultra-fast chargers, for example) and then identifies approaches to avoid or mitigate the issues. Of course, renewable energy plays a big part in this.

Charging hotspots

A charging hotspot is a place where a significant charging load may occur that is beyond the capacity of the network, whether that’s the limit of the street transformer, the feeder or a substation. The risk of a hotspot occurring depends on many things, including charger type (higher capacity chargers will have a greater impact), charging timing/length, driving distances of EV owners (which affects the amount of charging they need to do) and the location and density of chargers in an area. The report looks at the potential impacts of residential, workplace, fleet and public charging.

The report evaluated the risk of charging hotspots in different locations, and the potential to mitigate that with local solar generation or demand response. For example, it found that there’s a mid-level risk of charging hotspots occurring at the residential level, but a high chance of using rooftop solar or demand response to reduce the risk. As another example, the report identifies a low risk of hotspots at shopping centres as they are likely to use lower power chargers, with the shopping centre owners unlikely to upgrade them to higher power chargers if that requires significant connection upgrades/cost. Highway chargers are identified as having a high risk of becoming a hotspot—new network connections will be sized appropriately, but multiple charging stations on a long feeder could result in capacity issues.

In one interesting example that shows the result is not always predictable, London’s Waterloo bus garage thought it would need a network upgrade to cope with 51 electric buses, but, after the network upgrade got delayed, it found it could work within the limits of the existing connection by topping up buses during the day and only fully charging off-peak.

Managing capacity issues

While there is a potential for hotspots, there are many ways to reduce or eliminate the risk without needing significant network upgrades. There are three main strategies: price signals, infrastructure solutions and smart charging.

– Price signals

A price signal encourages charging at times when there’s less likely to be a capacity impact. Price signals can be static or dynamic. Static signals, like time-of-use pricing, have proved effective in the USA, Germany, UK and Japan. Evenergi reports

their own experience in the UK, where EV drivers actively seek out low-cost charging overnight. However, the report warns that they are a blunt instrument—they can be too effective, ineffective or have unintended consequences. For example, they can lead to too many vehicles charging at the same time, with peaks shifting to off-peak times (see Figure 1). Controlled load meters with lower tariffs, as currently used for hot water, are another option, and have the flexibility of being controlled by the network provider. In the past, such loads have been set to operate overnight at off-peak times, but the timing could be randomised or set to the daytime when there’s excess solar PV available. Dynamic prices or rewards that vary per day or per customer can also help randomise the load. Dynamic pricing trials are currently underway in Norway and California, with the latter trial finding success via an approach where prices are posted one day ahead.

Figure 1. Charging patterns with time-of-use (TOU) tariffs and without (RES), during summer weekdays at utility Progress Energy in North Carolina. The TOU bars show that the time-of-use tariff has shifted the peak to overnight. Image: adapted from U.S. Department of Energy bit.ly/2FdH9Nc

– Infrastructure solutions

In a recent ‘thoughtpiece’, the UK’s grid operator National Grid proposed to build a network of super-fast 350kW chargers located at similar sites to current petrol stations. If EVs could handle this charging rate (most currently can’t), these chargers could provide about 100km range in four minutes. National Grid projected that just 7000 of these stations with seven to nine chargers each would be sufficient—slightly less than the number of petrol pumps currently in the UK—and that this would reduce the need for private charging at home and work. The result would be less need to upgrade home connections and local networks; it would also provide charging capability for drivers without off-street parking.

The advantage of such an approach is that the charging load can be planned for and located to manage capacity issues.

Another infrastructure solution is pairing large-scale battery storage with charging stations. The report suggests this could be a way to deliver grid services and synchronise with over-generation of renewables to provide a positive impact on the wider grid.

Vehicle-to-grid is another possible approach, with signals used by the power network to charge/discharge vehicle batteries according to the needs of the grid. The Nissan Leaf is enabled for vehicle-to-grid and trials have been conducted; the report notes that current combined capacity of Leafs would be over 200MW globally.

Another option, of course, is to upgrade the network to make it better able to cope with variable loads like EV charging. The report discusses a UK Power Networks project called Active Response, which enables sharing of power between feeders and substations which it expects will “materialise 3.5GW of peak demand and save customers £271m by 2030.”

– Smart charging

Finally, and perhaps most promisingly, there’s smart charging, where the utility controls the timing of the EV charging. In its simplest form, this can be without knowledge of the vehicle’s state of charge or the owner’s driving intentions. Alternatively, it can be ‘paired control’, which allows a user to guarantee their car’s charge level and opt out of charge throttling events if the car is below a certain charge level. A pilot in Toronto, Canada, has illustrated the effectiveness of this approach (see Figure 2).

Whether you’re talking about vehicle owners charging at off-peak tariffs or grid operators throttling charging, control over the charging process is needed. The controller for this can be in the car—many EVs have charge controllers that enable them to avoid peak pricing events. More sophisticated controllers can even accept dynamic signals from the market. Alternatively, the controller can be in the wall charging device, the EVSE. These can simply manage charging times or accept dynamic signals to modulate charging, not just on-off control.

Signals can be based on time, peak load or grid frequency, or can be dynamic from the market operator for load shedding events. There can be value in this for vehicle owners—they may be able to avoid high demand tariffs or get paid for putting power into the grid. This can be particularly valuable for fleet operators.

Figure 2. The results of the FleetCarma smart charging program in Toronto, Canada, demonstrated the ability to reduce peak charging loads by half using demand management. Image: FleetCarma bit.ly/fc-rfcpt

How many chargers do we need?

There are some interesting statistics from overseas that can be used to guide the discussion. An extensive US study (17,000 charging locations and 8200 EVs, both PHEVs and battery EVs) showed that the majority of charging was done at home and work. The same study also showed that most people used just a few away-from-home charging locations, including their workplace.

While most charging is currently done at home or work, large numbers of public Mode 3 (up to 22 kW) charging stations are being installed to mitigate EV drivers’ range anxiety. These are currently under-used: in the USA, 75% of the public Mode 3 (known as Level 2 in the US) chargers are used less than four times per week, although popular sites such as shopping centres saw much higher usage, up to 7 to 11 times per day. But for those who can’t charge at home, a good network of chargers will be needed in the long run—the report suggests such a network is likely to happen when rapid charging roughly imitates the speed of petrol refuelling.

Fast chargers, common on highways, are used more frequently than the slower Mode 3 chargers—the US study showed a median of 7.2 uses per week, with a quarter averaging 15 uses per week and one being used 70 times per week. The most used ones were on major commuter routes within metropolitan areas.

Californian cities have, on average, 30 EVs per public charger, and currently Adelaide has about this ratio too. If that trend continues, the report suggests that Adelaide could have up to 3000 Mode 3 public chargers by 2025 (for 90,000 EVs, at the ‘strong’ end of AEMO’s EV uptake forecasts). The study also predicts that eventually, about 5% to 15% of the city’s public chargers could be DC rapid chargers (Mode 4). With larger batteries and ultra-fast chargers becoming available, there’s potential for a ‘petrol station’ model to emerge and a greater risk that these will be charging hotspots. However, required network upgrades would likely be paid for by the charging station operators.

The Evenergi report data on the relative number of regular (Mode 3/Level 2) chargers to DC rapid chargers in cities within major EV markets around the world, as of 2016, can be seen in Figure 3.

Figure 3. The relative number of regular chargers to DC rapid chargers in cities within major EV markets around the world. Image: Hall, D. and Lutsey, N. ‘Emerging Best Practices For Electric Vehicle Charging Infrastructure’. 2017.

Coordination with renewables

The report highlights that SA is the first region on the national electricity market that has so much rooftop solar that minimum demand shifted from overnight to midday; AEMO has forecast that SA may have negative minimum demand by 2025–26 when you factor in wind and large-scale solar. This means under-utilisation of capacity at certain times of the day (excess solar in the middle of the day and excess wind at night). Electric vehicles could play a significant role in improving utilisation and hence stabilising the grid by shifting their load to these times of minimum demand.

At the residential level, the benefits of charging from rooftop solar with and without a battery are also explored in the report, via analysis of several homes and their current load profiles; as might be expected, larger solar systems can reduce demand. Charging stations can also be beneficially paired with local solar generation, if there’s suitable roof space or if a large solar canopy can be constructed.

How much extra electricity?

As Cameron Munro notes in his article (p. 65), Australia’s passenger cars travelled a total of 180,000 million kilometres in 2018; assuming 180 Wh/km as an average electric car efficiency, the additional electricity required if all these cars were electric would be in the order of 32,400 GWh (neglecting transmission losses), or an increase of around 12%. So it’s not impossible to electrify the entire fleet.

Renew’s Andrew Reddaway calculated that an average daily EV commute uses around as much electricity as two showers. A standard 30 km round-trip commute requires about 6 kWh of electricity (at 200 Wh/km), while a 10-minute shower consumes about 3 kWh assuming a standard resistive heater, 15 °C cold water, 8 litres per minute shower flow and allowing for some heat leakage from the hot water tank.

Electric water heating doesn’t stress the grid because it tends to occur outside peak times—EV charging should be managed similarly.

More info:

Find the report ‘Managing the impacts of renewably powered electric vehicles on electricity distribution networks’ at bit.ly/EVEN-MTI. Evenergi is helping fleets and energy and automotive companies unlock the potential of EVs. Their next research project is to create software to help optimise networks for mass adoption of electric vehicles.

Author:

Robyn Deed

Renew magazine Managing Editor

Support our work

Renew is a not-for-profit organisation dedicated to arming you with the unbiased advice and information you need to make your home and community more sustainable. If you enjoy our content, please consider supporting us by becoming a Renew member or buying our publications. Your support is critical to helping us achieve our goals.